Rotating annular preventer and methods of use thereof

ABSTRACT

A rotating annular preventer having a body with at least one seal housed within the body, and the at least one seal being at least one rotatable seal. The at least one seal can seal the annulus around a tubular in the rotating annular preventer by actuating a first seal around the tubular by a piston and/or rotating a second seal sealingly engaged with the tubular, as the tubular is rotated, since the rotating annular preventer is configured to do both. An outlet, located axially below the piston in the side of the body, can divert fluid from an annulus surrounding the tubular.

BACKGROUND

Exploration for, location of, and extraction of subterranean fluids,including hydrocarbon fluids, typically involves drilling operations tocreate a well. Drilling operations, particularly drilling operationsinvolving rotary drilling, often utilize drilling fluids, also calledmuds, for a variety of reasons including lubrication, removal ofcuttings and other matter created during the drilling process, and toprovide sufficient pressure to ensure that fluids located insubterranean reservoirs do not enter the borehole, or wellbore, andtravel to the surface of the earth. Fluids located in subterraneanreservoirs are under pressure from the overburden of the earth formationabove them. Specialized equipment is used to provide control of allfluids used or encountered in the drilling of a well.

Conventionally, well pressure control equipment may include a blowoutpreventer (BOP) stack that sits atop of a wellhead. The BOP stack mayinclude ram BOP(s) and an annular BOP. An annular preventer is a largevalve used to control wellbore fluids. In this type of valve, thesealing element resembles a large rubber doughnut that is mechanicallysqueezed inward to seal on either pipe (drill collar, drillpipe, casing,or tubing) or the openhole. The ability to seal on a variety of pipesizes is one advantage the annular preventer has over the ram blowoutpreventer. Most BOP stacks contain at least one annular preventer at thetop of the BOP stack, and one or more ram-type preventers below.

Above the annular BOP is often a managed pressure drilling/underbalancedrilling rotating control device (RCD)/rotating head. The RCD/rotatinghead is a pressure-control device used during drilling for the purposeof making a seal around the drillstring while the drillstring rotates.Essentially, the RCD/rotating head is a diverter with holding pressurecapability. This device is intended to contain hydrocarbons or otherwellbore fluids and prevent their release to the atmosphere by divertingflow through an outlet below the sealing element.

SUMMARY OF DISCLOSURE

In one or more embodiments, a rotating annular preventer may include abody; at least one seal housed within the body and configured to sealagainst a tubular extending through the rotating annular preventer byactuation of a piston, wherein the at least one seal comprises at leastone rotatable seal; and an outlet in the side of the body to divertfluid from an annulus surrounding the tubular, wherein the outlet islocated axially below the piston.

In one or more embodiments, a method for using a rotating annularpreventer may include placing a tubular in the rotating annularpreventer about an central axis of the rotating annular preventer;sealing off the annulus around the tubular with the rotating annularpreventer by actuating a first seal around the tubular by a pistonand/or rotating a second seal sealingly engaged with the tubular as thetubular is rotated, the rotating annular preventer being configured todo both; and opening a valve to redirect a fluid in the annular aroundthe tubular out an outlet flow line that is below the first seal beingactuated by the piston.

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 illustrates a schematic view of a rotating annular preventeraccording to one or more embodiments of the present disclosure.

FIG. 2 illustrates a schematic view of a rotating annular preventeraccording to one or more embodiments of the present disclosure.

FIG. 3 illustrates a schematic view of a rotating annular preventeraccording to one or more embodiments of the present disclosure.

FIG. 4 illustrates a schematic view of a rotating annular preventeraccording to one or more embodiments of the present disclosure

FIG. 5 illustrates a schematic view of an apparatus of a rotatingannular preventer according to one or more embodiments of the presentdisclosure.

FIG. 6 illustrates a side view of an apparatus of a rotating annularpreventer according to one or more embodiments of the presentdisclosure.

FIG. 7 illustrates a cross-sectional view of an apparatus of a rotatingannular preventer according to one or more embodiments of the presentdisclosure.

FIG. 8 illustrates a cross-sectional view of an apparatus of a rotatingannular preventer according to one or more embodiments of the presentdisclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure are described below in detail withreference to the accompanying figures. Like elements in the variousfigures may be denoted by like reference numerals for consistency.Further, in the following detailed description, numerous specificdetails are set forth in order to provide a more thorough understandingof the claimed subject matter. However, it will be apparent to onehaving ordinary skill in the art that the embodiments described may bepracticed without these specific details. In other instances, well-knownfeatures have not been described in detail to avoid unnecessarilycomplicating the description.

While annular BOPs and rotating control device (RCD)/rotating heads areconventionally two separate pieces of equipment used in control of anoil well, embodiments of the present disclosure may allow for theintegration of the functionalities provided by the two together into asingle body/device. Such integrated device may be referred to as arotating annular preventer (RAP). Conventionally, an annular preventeris mainly used in well control scenarios to strip in and out thetubulars; however, a major drawback of the annular preventer, in thefield today, is the inability to divert fluid, necessitating the use ofa choke below the annular preventer. Further, conventionally a rotatinghead is used in drilling in under or at or over balanced scenarios orunder managed pressure drilling, where the fluid is maintained within apressurized system, rather than being open to the atmosphere. TheRCD/rotating head seals against the tubular as it rotates within thedevice (during drilling) and diverts the returned fluid from the annulusto a MPD manifold. Thus, in one or more embodiments, a rotating annularpreventer is an integrated managed pressure drilling/underbalanceddrilling rotating control device/rotating head and well control annularblowout preventer. The integration may take various forms, including theuse of a single body/bonnet and/or integration of internal parts.

By integrating the functionalities into a single device, in one or moreembodiments, the RAP of the present disclosure may divert fluid, sealoff the annulus while tubulars are moving up and downwards and/orrotating, seal off the wellbore when there are no tubulars in it, and/orstrip in and out the tubulars in well control situation. The RAP can beused on and off while drilling through different formations and depthswhen is needed, or tripping in and out or stripping in and out whilesecuring the well. The RAP as a single piece equipment may be installed,for example, at the top of the BOP stack, in the place of a conventionalannular preventer, with a bell nipple being installed at the top of theRAP.

Now referring to FIG. 1, the integrated functionality of a rotatingannular preventer according to one or more embodiments is shown. In FIG.1, a tubular 100 is positioned about a central axis 101. Those skilledin the art would appreciate how the tubular 100 may be any string oftubulars that connect end-to-end such as, but not limited to, drill pipestring. The tubular 100 extends into a wellbore through an annularpreventer 102. Annular preventer 102 includes an annular preventer (AP)seal 103 or packing element that is positioned about the central axis101. Adjacent to a bottom or outer radial surface of AP seal 103 is apiston 104 having a wedge face which interfaces/abuts the AP seal 103.Further, FIG. 1 illustrates that the AP 103 seal and the piston 104 bothhave a triangular cross-section; however, it may be understood that theAP seal 103 may have any geometry suitable for tubular sealing andactuation, such as by a corresponding face of the piston 104. The APseal 103 is configured to close around tubular 100 when piston 104 movesaxially upwards, thus sealing off an annulus between tubular 100 andwellbore (not shown). Further, in one or more embodiments, AP seal 103may seal upon itself (without a tubular 100 being present), sealing offthe wellbore from the environment. AP seal may be selected to havedurability for long lasting operations under harsh physical and chemicalconditions, including exposure to sharp edges of tubulars, H₂S, CO₂,corrosive materials, heat, high velocity stripping, tong marks on tooljoints, rough hard banding, and/or various mud types and additives.Further, AP seal 103 may also seal against a variety of sizes and shapesof tubulars, collars, tool joints, etc., as well as on itself inscenarios where no tubular is present in the well. In one or moreembodiments, AP seal or packing element 103 may include an elastomericmaterial having a plurality of supporting metallic inserts or particlesmolded or otherwise provided therein.

Piston 104 may be hydraulically actuated to engage and disengage the APseal 103, thereby opening and closing the annular preventer 102. Awellbore pressure 105 may optionally be used in conjunction with thehydraulically actuated piston 104 to close the AP seal 103 around thetubular 100. The wellbore pressure 105 can be applied directly orindirectly to the hydraulically actuated piston 104 to help close the APseal 103 around the tubular 100 by any passageway or fluid communicationbetween the annulus and the piston 104. By hydraulically actuatingpiston 104, piston 104 is not dependent on the wellbore pressure 105,thus allowing the piston 104 to engage and disengage the AP seal 103under any wellbore pressure 105. Additionally, an outlet flow line 106is disposed below AP seal 103, such as at a bottom of the annularpreventer 102, to allow a flow of wellbore fluid out of the annularpreventer 102. Once an AP seal 103 seals around tubular 100 and valve107 is opened, the outlet flow line 106 will divert wellbore fluid fromthe annulus (not shown) since the AP seal 103 has closed the annularflowpath around tubular 100. Additionally, the valve 107 may be ahydraulically remote valve (HCR) to open and close the valvehydraulically and remotely. Furthermore, a check valve 111 or a one wayvalve, to prevent reverse flow of the fluid, may be used in conjunctionwith the valve 107. As seen by FIG. 1, the check valve 111 is positionednear the valve 107 on an opposite end of the outlet flow line 106.Further, it is also envisioned that the check valve 111 may also beplaced between outlet flow line 106 and valve 107, or there may be aplurality of check valves 111, such as on both sides of the valve 107.Further, in the illustrated embodiment, piston 104 is hydraulicallyactuated; however, the wellbore pressure 105 may enhance the sealing ofthe AP seal 103 with the tubular 100. The hydraulic actuation may beconsidered an active sealing system, whereas use of wellbore pressurealone is a passive sealing system. Embodiments using both hydraulicactuation in combination with the wellbore pressure, as illustrated inFIG. 1, may be referred to as a combination sealing system.

Further, a bearing assembly 108 is disposed on the piston 104 at anouter radial surface thereof. The bearing assembly 108 allows for therotation of piston 104 (and AP seal 103 via its engagement with piston104) within the annular preventer 102, unlike conventional annular BOPs.While not specifically illustrated, it is envisioned that heat generatedby the bearing assembly 108 may be transferred therefrom with the use ofa circulating hydraulic lubricant oil system. The rotation of the APseal 103 and piston 104 may result from rotation of tubular 100 sealedat an inner surface of AP seal 103. Thus, as tubular 100 rotates, thesealing engagement between tubular 100 and AP seal 103 and theengagement between AP seal 103 and piston 104 causes the AP seal 103 andpiston 104 to rotate along with tubular 100. Thus, actuation of thepiston 104 may cause seal 103 to seal against the tubular either in wellcontrol situations or when it is desired to drill under managedpressure. Additionally, at least one or more hydraulic lines (not shown)are coupled to the piston 104 for actuation thereof. In one or moreembodiments, the piston 104 may have one hydraulic line (not shown)configured to disengage the piston 104 from the AP seal 103 and anotherhydraulic line (not shown) to engage the piston 104 to the AP seal 103.

While FIG. 1 shows the bearing assembly located radially outside of thepiston 104 (and AP seal 103), the present disclosure is not so limited.Rather, in the embodiment illustrated in FIG. 2, a bearing assembly 109is disposed in between the AP seal 103 and the piston 104. Further, aswith bearing assembly 108 described above, bearing assembly 109 may beprovided with a circulating hydraulic lubrication oil system (not shown)to transfer heat away from bearing assembly 108 during use/rotation ofseal 103. Specifically, as a tubular 100 rotates within annularpreventer 102, if piston 104 has been actuated (hydraulically or bywellbore pressure 105 or by a combination thereof), AP seal 103 willrotate within piston 104 based on the sealing engagement of AP seal 103and tubular 100.

Further, as described above, annular preventer 102 also includes anoutlet flow line 106 that, upon opening of valve 107, may divertwellbore fluid from the annulus upon sealing engagement of AP seal 103with tubular 100 (or itself if no tubular is present). Additionally, acheck valve 111 or a one way valve, to prevent reverse flow of thefluid, may be used in conjunction with the valve 107. As seen by FIG. 2,the check valve 111 is positioned near the valve 107 on an opposite endof the outlet flow line 106. Further, it is also envisioned that thecheck valve 111 may also be placed between outlet flow line 106 andvalve 107, or there may be a plurality of check valves 111, such as onboth sides of the valve 107. Furthermore, FIG. 3 shows anotherembodiment, where bearing assembly 108 is disposed on a radially outersurface of piston 104 and a second bearing assembly 109 is disposedbetween the AP seal 103 and the piston 104, both of which may includelubrication systems for transferring heat away therefrom. Thus, as atubular 100 rotates within annular preventer 102, if piston 104 has beenactuated (hydraulically or by wellbore pressure 105 or by a combinationthereof), AP seal 103 will rotate with or within piston 104 based on thesealing engagement of AP seal 103 and tubular 100. Further, as describedabove, annular preventer 102 also includes an outlet flow line 106 that,upon opening of valve 107, may divert wellbore fluid from the annulusupon sealing engagement of AP seal 103 with tubular 100. Furthermore, acheck valve 111 or a one way valve, to prevent reverse flow of thefluid, may be used in conjunction with the valve 107. As seen by FIG. 3,the check valve 111 is positioned near the valve 107 on an opposite endof the outlet flow line 106. Further, it is also envisioned that thecheck valve 111 may also be placed between outlet flow line 106 andvalve 107, or there may be a plurality of check valves 111, such as onboth sides of the valve 107.

Referring now to FIG. 4, an embodiment illustrating an exampleimplementation of the annular preventer of the present disclosure. Forexample annular preventer 102 has a body 110 housing AP seal 103 thatcan seal against a tubular (not shown) extending through a bore of theannular preventer 102 or in some embodiments, can form a seal uponitself (when no tubular is present) to seal off the wellbore. Thesealing by AP seal 103 is actuated by a wedge piston 104 (which may behydraulically actuated by hydraulic fluid pumped in chambers adjacent tothe wedge piston 104) and/or passively achieved through the wellborepressure. AP seal 103 may rotated within body 110, such as when sealedagainst a tubular (not shown) that is rotated within the annularpreventer 102. AP seal 103 may rotate, for example, due to theincorporation of a bearing assembly 108 that is on a radial outersurface of AP seal 103. It is also envisioned that a bearing assembly108 may be omitted (in this embodiment or any of the above embodiments)and the AP seal 103 may rotate within the annular preventer based on anon-bearing assembly mechanism, such as the incorporation of a lubricantat the outer radial surface of the AP seal so that the AP seal 103 maymove independently from body 110 or annular preventer 102 (such as in arotational direction). Upon sealing of AP seal 103 (either to a tubularor on itself), fluids present in the annulus of the wellbore may flowthrough an outlet flow line 106 present in the body 110 to be divertedoutside of the annular preventer 102 (upon opening of valve 107, whichmay be hydraulically or manually operated). As illustrated, outlet flowline 106 is located below AP seal 103 and is in fluid communication withthe annulus via a passageway (not shown) formed in the body 110.Furthermore, a check valve 111 or a one way valve, to prevent reverseflow of the fluid, may be used in conjunction with the valve 107. Asseen by FIG. 4, the check valve 111 is positioned near the valve 107 onan opposite end of the outlet flow line 106. Further, it is alsoenvisioned that the check valve 111 may also be placed between outletflow line 106 and valve 107, or there may be a plurality of check valves111, such as on both sides of the valve 107. Further, while body 110 isdescribed as being the outer housing for the internal annular preventer102 components, it is also appreciated that the body may have multiplecomponents, such as a body and bonnet, etc. that may be attachedtogether to form a complete outer structure. The precise arrangement ofsuch components is not a limitation on the present disclosure. However,it is envisioned that in one or more embodiments, all of the internalcomponents providing the rotating annular preventer functionalitiesreside within a single outer “body” or structure (even if the outerstructure is formed from multiple parts). In that sense, it isenvisioned that the functionality of the device is not achieved withoutassembly of the outer structure together. In contrast, a conventionalannular preventer or RCD could function independently without connectionof the two together (such as by flanges).

Referring now to FIG. 5, another embodiment of an annular preventer isshown.

While the above described embodiments show a single seal (that isrotatable) in order to combine the annular BOP and RCD functionalitiesinto a single packing element, the present disclosure is not so limited.Rather, embodiments may also use, within a single body, multiple seals(at least one of which is rotatable) and achieve a device of the presentdisclosure. For example, according to one or more embodiments, arotating annular preventer 400 has functionalities for a rotatingcontrol device in an upper region 401 and an annular preventer in alower region 402 in a single body 410. Further, while body 410 isdescribed as being the outer housing for the internal rotating annularpreventer 400 components, it is also appreciated that the body may havemultiple components, such as a body and bonnet, etc. that may beattached together to form a complete outer structure. The precisearrangement of such components is not a limitation on the presentdisclosure. The rotating control device 401 is axially above the annularpreventer 402.

Still referring to FIG. 5, the rotating control device upper region 401may provide functionality that enables managed pressure drilling andseal against a moving tubular (rotationally and axially moving) asdrilling fluid is pumped into the wellbore and returns to the surfacethrough the annulus. Specifically, rotating control device upper region401 includes a rotating control device (RCD) seal or packing unit 403housed within body 410. On the outer radial surface of RCD seal 403 is aRCD bearing assembly 408, which allows for the rotation of the RCD seal403 within the rotating control device 401. Further, as described above,heat generated by bearing assembly 408 may be transferred elsewhere by acirculating hydraulic lubricant oil system (not shown).

As a tubular 100 rotates within the rotating annular preventer 400, theRCD seal 403 will rotate based on the sealing engagement of the RCD seal403 and the tubular 100. The engagement of RCD seal 403 with tubular 100occurs when the annular preventer 402 (described below) is open.Specifically, RCD seal 403 engages against tubular 100 extending througha bore of the rotating annular preventer 400 due to wellbore pressure105. Wellbore pressure 105 may be transmitted through any passageway orthe like that can provide fluid communication between the annulus andRCD seal 403. Upon engaging with tubular 100, RCD seal 403 is intendedto contain hydrocarbons or other wellbore fluids and prevent theirrelease to the atmosphere. Rather, engagement of RCD seal 403 withtubular 100 will result in wellbore fluids being diverted from theannulus through the outlet flow line 106 (upon opening of valve 107) sothat drilling may continue under managed pressure. Outlet flow line 106is located towards the bottom end of body 410.

Below rotating control device upper region 401 and above outlet flowline 106 is annular preventer lower region 402, which provides wellcontrol functionality. In one or more embodiments, the annular preventerlower region 402 includes an annular preventer (AP) seal 103 that ispositioned about the central axis 101 (and an optional tubular 100).When open, AP seal 103 may have an internal diameter that, at a minimum,is the same as a ram BOP stack (not shown), thereby allowing easypassage of the tubulars therethrough without any restriction. Adjacentto a bottom or outer radial surface of AP seal 103 is a piston 104having a wedge face. Further, FIG. 5 illustrates that AP seal 103 andthe piston 104 both have a triangular cross-section; however, it may beunderstood that the AP seal 103 may have any geometry suitable fortubular sealing and actuation, such as by a corresponding face of thepiston 104. The AP seal 103 is configured to close around tubular 100when piston 104 moves up, thus sealing off an annulus between tubular100 and wellbore (not shown). Piston 104 may be hydraulically actuatedto engage and disengage the AP seal 103, thereby opening and closing theannular preventer 402. A wellbore pressure 105 may be used inconjunction with the hydraulically actuated piston 104 to close the APseal 103 around the tubular 100. By hydraulically actuating piston 104,piston 104 is not dependent on the wellbore pressure 105 (though, may beenhanced by wellbore pressure 105), thus allowing the piston 104 toengage and disengage the AP seal 103 under any wellbore pressure 105.Furthermore, the piston 104 can engage the AP seal 103 to seal uponitself (when no tubular is present) to seal off the wellbore.Additionally, an outlet flow line 106 is disposed below AP seal 103,such at a bottom of the annular preventer 402, to allow a flow ofwellbore fluid out of the annular preventer 402. Once an AP seal 103seals around tubular 100 and valve 107 is opened, the outlet flow line106 will divert wellbore fluid from the annulus (not shown) since the APseal 103 has closed the annular flowpath around tubular 100.Furthermore, a check valve 111 or a one way valve, to prevent reverseflow of the fluid, may be used in conjunction with the valve 107. Asseen by FIG. 5, the check valve 111 is positioned near the valve 107 onan opposite end of the outlet flow line 106. Further, it is alsoenvisioned that the check valve 111 may also be placed between outletflow line 106 and valve 107, or there may be a plurality of check valves111, such as on both sides of the valve 107. Further, in the illustratedembodiment, piston 104 is hydraulically actuated; however, the wellborepressure 105 may enhance the sealing of the AP seal 103 with the tubular100. As stated above, the hydraulic actuation may be considered anactive sealing system, whereas use of wellbore pressure alone is apassive sealing system. As described above, the rotating control deviceupper region 401 uses wellbore pressure as a passive sealing system, andthe annular preventer lower region 402 is an active sealing system, allwithin a single body 410.

Now referring to FIG. 6, according to one or more embodiments, arotating annular preventer 600 has a body 601, which has an upperportion 602 and a lower portion 603. Furthermore, a rotating controldevice 610 is housed within in the upper portion 602 of body 601, and anannular preventer 611 is housed within the lower portion 603 of body601. The rotating control device 610 and annular preventer 611 are notseparate devices per se but contain distinct components that providedistinct functionality and thus are referred to as such. However, therotating annular preventer 600 is a single device having multiplefunctionality all housed within a single body 601. Additionally, thelower portion 603 has an outlet flow line 604 disposed on its outer walland a valve 605 to open and close flow through the outlet flow line 604to a fluid transport line (not shown). Additionally, the valve 605 maybe a hydraulically remote valve (HCR) to open and close the valvehydraulically and remotely. Furthermore, a check valve 612 or a one wayvalve, to prevent reverse flow of the fluid, may be used in conjunctionwith the valve 605. As seen by FIG. 6, the check valve 612 is positionednear the valve 605 on an opposite end of the outlet flow line 604.Further, it is also envisioned that the check valve 612 may also beplaced between outlet flow line 604 and valve 605, or there may be aplurality of check valves 612, such as on both sides of the valve 605.Further, while body 601 is described as being the outer housing for theinternal rotating annular preventer 600 components (including componentsproviding functionality for rotating control device 610 and annularpreventer 611), it is also appreciated that the body may have multiplecomponents, such as a body and bonnet, etc. that may be attachedtogether to form a complete outer structure. The precise arrangement ofsuch components is not a limitation on the present disclosure. Across-section is taken along the central axis 101 to show the internalworkings of the rotating annular preventer 600, is shown in FIG. 7.

Referring to FIG. 7, according to one or more embodiments, the rotatingcontrol device 610 has a double seal configuration 703. The double sealconfiguration 703 has as a first rotating control device (RCD) seal 704and a second rotating control device (RCD) seal 705 placed above the RCDseal 704. For example, the second RCD seal 705 may act as backup to theRCD seal 704. As such the case, when damage occurs to the first RCD seal704 or the seal integrity of the first RCD seal 704 is compromised,second PCD seal 705 may provide sealing engagement with tubular 101.There is no limit on the number of RCD seals that may be present. RCDseals 704, 705, together with other components of rotating controldevice 610, may enable managed pressure drilling to occur. Specifically,RCD seals against a moving tubular (rotationally and axially moving) asdrilling fluid is pumped into the wellbore, returns to the surfacethrough the annulus, and is diverted from rotating annular preventerthrough outlet flow line 604. Thus, rotating control device 610functionality may be used when the annular preventer (performing wellcontrol functionality) 611 is open. Specifically, a wellbore pressure(shown in FIG. 5) is used to engage the RCD seal 704 with the tubular100 extending through a bore of the rotating annular preventer 600, thusmaking a seal around the tubular 100 while the tubular 100 rotates andmoves axially within the well. Wellbore pressure (shown in FIG. 5) maybe transmitted through any passageway or the like that can provide fluidcommunication between the annulus and RCD seal 704. Additionally, thesecond RCD seal 705 will also use the wellbore pressure to make a sealaround the tubular 100 while the tubular 100 rotates. Furthermore, arotating control device (RCD) bearing assembly 706 is disposed on theRCD seal 704 and the second RCD seal 705 at outer radial surfacesthereof. The RCD bearing assembly 706 allows for the rotation of eitherthe first RCD seal 704 or the second RCD seal 705 within the rotatingcontrol device 610. Thus, as a tubular 100 rotates within the rotatingannular preventer 610, the first RCD seal 704 or the second RCD seal 705will rotate based on the sealing engagement with the tubular 100.

Still referring to FIG. 7, according to one or more embodiments, theannular preventer 611 is below rotating control device 610, and both arehoused within a single outer body structure includes an annularpreventer (AP) seal 707 that is positioned about the central axis 101.Adjacent to a bottom or outer radial surface of AP seal 707 is a piston708 having a wedge face. Further, FIG. 7 illustrates that AP seal 707and the piston 708 both have a cross-section suitable for tubularsealing and actuation, such as by a corresponding face of the piston708. The AP seal 707 is configured to close around tubular 100 whenpiston 708 moves up, thus sealing off an annulus between tubular 100 andwellbore (not shown). Piston 708 may be hydraulically actuated to engageand disengage the AP seal 707, thereby opening and closing the annularpreventer 611. A wellbore pressure (shown in FIG. 5) may be used inconjunction with the hydraulically actuated piston 708 to close the APseal 707 around the tubular 100, similar to as described above. Byhydraulically actuating piston 708, the piston 708 is not dependent onthe wellbore pressure (shown in FIG. 5), thus allowing the piston 708 toengage and disengage the AP seal 708 under any wellbore pressure (shownin FIG. 5). Furthermore, the piston 708 can engage the AP seal 707 toseal upon itself (when no tubular is present) to seal off the wellbore.Additionally, an outlet flow line 604 is disposed below AP seal 707,such at a bottom of the annular preventer 611, to allow a flow ofwellbore fluid out of the annular preventer 611. Once an AP seal 707seals around tubular 100 and valve 605 is opened, the outlet flow line604 will divert wellbore fluid from the annulus (not shown) since the APseal 707 has closed the annular flowpath around tubular 100.Furthermore, a check valve 612 or a one way valve, to prevent reverseflow of the fluid, may be used in conjunction with the valve 605. Asseen by FIG. 7, the check valve 612 is positioned near the valve 605 onan opposite end of the outlet flow line 604. Further, it is alsoenvisioned that the check valve 612 may also be placed between outletflow line 604 and valve 605, or there may be a plurality of check valves612, such as on both sides of the valve 605. Further, in the illustratedembodiment, piston 708 is hydraulically actuated; however, the wellborepressure (shown in FIG. 5) may enhance the sealing of the AP seal 707with the tubular 100. The hydraulic actuation may be considered anactive sealing system, whereas use of wellbore pressure alone is apassive sealing system. As described above, the rotating control device610 uses wellbore pressure, and is thus a passive sealing system, andthe annular preventer 611 is an active sealing system.

Referring now to FIG. 8, another embodiment of the rotating controldevice 610 of the rotating annular preventer 600 is shown. In thisembodiment, the rotating control device 610 has a single sealconfiguration 803. As such, the single seal configuration 803 only hasthe rotating control device (RCD) seal 704. With the annular preventer611 open, a wellbore pressure (shown in FIG. 5) is used to engage theRCD seal 704 with the tubular 100 extending through a bore of therotating annular preventer 600, thus, making a seal around the tubular100 while the tubular 100 rotates. Wellbore pressure (not shown) may betransmitted through any passageway or the like that can provide fluidcommunication between the annulus and RCD seal 704. Furthermore, arotating control device (RCD) bearing assembly 706 is disposed on theRCD seal 704 at an outer radial surface thereof. The RCD bearingassembly 706 allows for the rotation of the RCD seal 704 within therotating control device 610. Thus, as a tubular 100 rotates within therotating annular preventer 610, the RCD seal 704 will rotate based onthe sealing engagement with the tubular 100.

Thus, there are a number of variations that may be made on the rotatingannular preventer of the present disclosure. The single device mayintegrate the conventionally two separate devices/functionalities byjust sharing the bonnet/body for the RCD and annular preventer, or thedevice may integrate internal components. Further, as also describedabove, the various sealing elements (also referred to in the art as apacking assembly) can be operated as an active sealing system, passivesealing system, or with combinations thereof. While the rotating annularpreventer integrates two functions of well control and managed pressuredrilling, it is understood that the dynamic pressure rating of thedevice (considered while moving tubulars) may be less than static rating(considered when no tubulars are present) due to movement of tubulars(either axially or rotationally).

Further, as described, embodiments of the present disclosure may includeone or more hydraulic lines, such as for the hydraulically actuatedpiston, for cooling of a bearing assembly, etc. In one or moreembodiments, hydraulic lines for opening and closing the annularpreventer (such as by moving the piston) can be distinct from thelubricant oil lines. Further, it is also envisioned that hydraulic linesfor operating the RAP in well control situations can be separate fromhydraulic lines for operating the RAP during managed pressure drillingand underbalanced drilling operations. Sealing elements can be dividedinto separate compartments for MPD/UBD operation or well controloperation. When the RAP is not needed, it will be fully opened byapplying hydraulic pressure to position/reposition its piston axiallydownward, allowing the retraction/repel of the sealing elements (packingassembly). When RAP is needed, the piston will move upward to the closedposition and cause the sealing elements (packing assembly) to squeezeinward towards any object or itself in order to seal off completely theannulus or even open wellbore. These and other actuations and tasks canbe mechanized and automated to fulfill all the required tasks fromhealth monitoring and preventive maintenance as well as operation andwell construction. Specifically, the entire process can bemechanized/automated and a software used to control the operation.

It is also envisioned that the sealing pressure of the one or moresealing elements can be adjusted and regulated (either automatically ormanually), particularly for passing different shape of tubulars (forexample, due to collars, stabilizers, tool joints, etc.) under a varietyof wellbore pressures. In an active or combination system, whendifferent geometry of tubulars are passing through the sealed elementsunder different wellbore conditions, the pressure of hydraulic oilsystem can be adjusted and regulated automatically or manually to ensurethe optimum proper sealing of the annulus.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

What is claimed is:
 1. A rotating annular preventer, comprising: a body;at least one seal housed within the body and configured to seal againsta tubular extending through the rotating annular preventer by actuationof a piston, wherein the at least one seal comprises at least onerotatable seal; and an outlet in the side of the body to divert fluidfrom an annulus surrounding the tubular, wherein the outlet is locatedaxially below the piston.
 2. The rotating annular preventer of claim 1,wherein a single seal is both the at least one rotatable seal and theseal actuated by the piston.
 3. The rotating annular preventer of claim2, further comprising a bearing assembly disposed on an outer radialsurface of the single seal, thereby providing for the single seal to berotatable.
 4. The rotating annular preventer of claim 2, furthercomprising a bearing assembly disposed on an outer radial surface of thepiston, thereby providing for the single seal to be rotatable.
 5. Therotating annular preventer of claim 2, further comprising a firstbearing assembly disposed on an outer radial surface of the piston and asecond bearing assembly disposed on an outer radial surface of thesingle seal, thereby providing for the single seal to be rotatable. 6.The rotating annular preventer of claim 1, wherein the body furthercomprises an upper portion containing a rotating control device and alower portion containing an annular preventer.
 7. The rotating annularpreventer of claim 6, wherein the rotating control device comprises theat least one rotatable seal and the annular preventer comprises the atleast one seal actuated by the piston.
 8. The rotating annular preventerof claim 7, further comprising a bearing assembly disposed on an outerradial surface of the at least one rotatable seal, thereby providing forrotation of the at least one rotatable seal.
 9. The rotating annularpreventer of claim 6, wherein the rotating control device comprises tworotatable seals.
 10. The rotating annular preventer of claim 9, whereinthe each of the two rotatable seals is rotatable due to a bearingassembly disposed on an outer radial surface of each of the tworotatable seals.
 11. The rotating annular preventer claim 1, wherein theat least one seal is reinforced with a metallic material.
 12. Therotating annular preventer of claim 1, further comprising at least oneor more lubrication systems disposed in the body.
 13. The rotatingannular preventer of claim 1, wherein the outlet flow line furthercomprises at least one or more valves to open and close the outlet flowline.
 14. A method for using a rotating annular preventer, comprising:placing a tubular in the rotating annular preventer about an centralaxis of the rotating annular preventer; sealing off the annulus aroundthe tubular with the rotating annular preventer by actuating a firstseal around the tubular by a piston and/or rotating a second sealsealingly engaged with the tubular as the tubular is rotated, therotating annular preventer being configured to do both; and opening avalve to redirect a fluid in the annular around the tubular out anoutlet flow line that is below the first seal being actuated by thepiston.
 15. The method of claim 14, wherein the first seal and thesecond seal are the same seal.
 16. The method of claim 14, wherein therotation of the at least one seal is by a bearing assembly.
 17. Themethod of claim 14, further comprising lubricating the at least one sealwith a lubricant to help enable rotation with or without a bearingassembly.
 18. The method of claim 14, further comprising directing theannulus fluid from the outlet flow line to a fluid transport line. 19.The method of claim 14, wherein the first seal actuated by the piston isaxially below the second seal rotated with the tubular.
 20. The methodof claim 14, wherein the second seal is sealingly engaged with thetubular by a wellbore pressure.